Production of oil and gas from subterranean formations is dependent on many factors. These hydrocarbons must usually migrate through a low permeable formation matrix to drain into the wellbore. In many formations, the permeability is so low that it hinders the well's production rate and overall potential. In other wells, the near wellbore is damaged during drilling operations and such damage often results in less than desirable well productivity. Hydraulic fracturing is a process designed to enhance the productivity of oil and gas wells or to improve the injectivity of injection wells.
In the fracturing process, a viscous fluid is injected into the wellbore at such a rate and pressure as to induce a crack or fracture in the formation. Once the fracture is initiated, a propping agent, such as sand, is added to the fluid just prior to entering the wellbore. This sand laden slurry is continuously injected causing the fracture to propagate or extend. After the desired amount of proppant has been placed in the reservoir, pumping is terminated, and the well is shut-in for some period of time. Later, the well is opened, initially to recover a portion of the treating fluid and later the hydrocarbons. The hydraulic fracturing process is successful because the hydrocarbons are now able to drain into the propped fracture that serves as a highly conductive channel leading directly to the wellbore.
The fracturing treatment is dependent, in part, on the properties of the fracturing fluid. The fluid must attain high viscosities, minimize solvent loss to the formation matrix (known in the art as fluid loss control) and adequately suspend the proppant. The fracturing fluid is prepared by first dissolving polymers in a solvent. Generally, the solvent is water which is often made saline or contains other additives to minimize clay expansion and migration in the formation matrix. The fracturing fluids are typically composed of water soluble polymers, crosslinking agents, breakers and other additives, such as surfactants, which are employed to prevent well specific problems such as water blocks or emulsions.
The water soluble polymers most often used are either guar gum or a guar gum derivative. The derivatives usually are hydroxypropyl guar (HPG), carboxymethyl guar (CMG) or carboxymethylhydroxypropyl guar (CMHPG). Less often, cellulose derivatives such as hydroxyethyl cellulose (HEC) or carboxymethylhydroxypropyl cellulose are used, but are generally cost prohibitive. Lastly, biopolymers such as xanthan gum have been used in rare occasions. At polymer concentrations usually ranging from 0.24 to 0.72 weight percent, the viscosities of the solutions made from these polymers are too low in most instances to be used as a fracturing fluid. As a reference, a 0.48 weight percent polymer solution (i.e. without a crosslinking agent) generally provides a viscosity of less than 50 centipoise (cps) at 511 s.sup.-1. The viscosity of polymer solutions may be enhanced by the addition of a crosslinking agent. Typical crosslinking agents contain titanium, zirconium or boron ions. These agents work by binding the polymer chains together. Since the viscosity is derived exponentially from the polymer's molecular size, binding the polymers together dramatically increases their size and consequently, the viscosity.
Traditionally, polymer concentration has been viewed as the important factor in obtaining fracturing fluid stability, i.e. maintenance of viscosity at an acceptable level, at a prescribed temperature, for a defined period of time. The convention in the art has been to increase polymer concentration or loading to increase stability for long pumping times or for treating formations at high temperatures. For example, in wells having high temperatures in excess of about 350.degree. F. (177.degree. C.), the polymer loading may exceed 0.72 weight percent. At the other extreme, a useful fracturing fluid could not be obtained at polymer concentrations of less than 20 pounds per thousand gallons (ppt), or 0.24 weight percent. In practice, an increase in viscosity above the polymer solution is not obtained and many times the polymer may precipitate from solution when crosslinker is added. However, it would be highly desirable to have stable, crosslinked fracturing fluids using polymer loadings of 20 ppt less.